Methods and compositions of using viscoelastic surfactants as diversion agents

ABSTRACT

A wellbore fluid including a first surfactant, a second surfactant, an activator and an aqueous base fluid is provided. The first surfactant has a structure represented by Formula (I):where m is an integer ranging from 2 to 3, and n, o, and k are each, independently, integers ranging from 2 to 10. The second surfactant has a structure represented by Formula (III):where R2 is a C15-C27 hydrocarbon group or a C15-C29 substituted hydrocarbon group, R3 is a C1-C10 hydrocarbon group, and p and q are each, independently, an integer ranging from 1 to 4. A method for treating a hydrocarbon-containing formation with the wellbore fluid is also provided.

BACKGROUND

Well stimulation enables the improved extraction of hydrocarbon reservesthat conventional recovery processes, such as gas or water displacement,cannot access. One well stimulation technique is matrix stimulation,which may also be referred to as matrix acidizing treatment. In matrixstimulation, an acidic fluid is injected into a formation at a pressurebelow the fracture pressure and is used to stimulate a reservoir byreacting with the reservoir rock, thereby dissolving the rock to createa pathway for hydrocarbon production.

However, when the acidic fluid has a low viscosity, the acid may havelimited penetration into the formation and only react at the face of therock. This is not an effective method for stimulating the reservoir as aconductive pathway for hydrocarbon production is not created. Further,most of the reservoirs have heterogeneous permeabilities which result inthe low viscosity acid primarily penetrating the high permeable zones inthe reservoir and leaving most of the low permeability zones untreated.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

In one aspect, embodiments of the present disclosure relate to awellbore fluid comprising a first surfactant, a second surfactant, anactivator and an aqueous base fluid. The first surfactant has astructure represented by Formula (I):

where m is an integer ranging from 2 to 3, and n, o, and k are each,independently, integers ranging from 2 to 10. The second surfactant hasa structure represented by Formula (III):

where R² is a C₁₅-C₂₇ hydrocarbon group or a C₁₅-C₂₉ substitutedhydrocarbon group, R³ is a C₁-C₁₀ hydrocarbon group, and p and q areeach, independently, an integer ranging from 1 to 4.

In another aspect, embodiments disclosed herein relate to a method fortreating a hydrocarbon-containing formation comprising injecting awellbore fluid into a high permeability zone of a hydrocarbon-containingformation, where the high permeability zone increases the temperature ofthe wellbore fluid, resulting in the wellbore fluid having an increasedviscosity. The wellbore fluid comprises a first surfactant, a secondsurfactant, an activator and an aqueous base fluid. The first surfactanthas a structure represented by Formula (I):

where m is an integer ranging from 2 to 3, and n, o, and k are each,independently, integers ranging from 2 to 10. The second surfactant hasa structure represented by Formula (III):

where R² is a C₁₅-C₂₇ hydrocarbon group or a C₁₅-C₂₉ substitutedhydrocarbon group, R³ is a C₁-C₁₀ hydrocarbon group, and p and q areeach, independently, an integer ranging from 1 to 4.

Other aspects and advantages of the claimed subject matter will beapparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a reaction scheme for preparing a surfactant in accordancewith one or more embodiments.

FIG. 2 is a block flow diagram of a method in accordance with one ormore embodiments.

FIG. 3 is a reaction scheme for preparing a surfactant in accordancewith one or more embodiments.

DETAILED DESCRIPTION

Embodiments in accordance with the present disclosure generally relateto a surfactant mixture, wellbore fluids that contain surfactantmixtures and an activator, and methods of using the fluids in processessuch as acid stimulation and enhanced oil recovery (EOR). Thesurfactants may be viscoelastic. Methods of one or more embodiments mayinvolve injecting the wellbore fluids into a formation, exposing thefluid to an increased temperature and resulting in the wellbore fluidhaving an increased viscosity. Such methods may modify the injectionprofile of the formation a well stimulation treatment by divertingstimulation fluid to lower permeability zones of the reservoir.

The wellbore fluids may be low-viscosity aqueous solutions that increasein viscosity under downhole conditions. The wellbore fluids maydemonstrate increased stability under high temperature and pressureconditions, making them highly suitable for use in downholeenvironments. When the wellbore fluid contacts a produced hydrocarbonits viscosity may drastically reduce, enabling easy flowback of thefluid post treatment. As the viscosifying material used in the presentdisclosure does not contain any solid particulates, it will bepotentially non-damaging to the formation due to effective flowback andno residual deposition inside the formation.

One or more embodiments of the present disclosure relate to a wellborefluid comprising a first surfactant, a second surfactant, an activatorand an aqueous base fluid. The first surfactant may be apiperazine-based surfactant having a structure represented by Formula(I):

where m is an integer ranging from 2 to 3, and n, o, and k are each,independently, integers ranging from 2 to 10.

In one or more embodiments, the first surfactant may be a piperazinebased surfactant such as3,3′,3″,3′″-(piperazine-1,4-diium-1,1,4,4-tetrayl)tetrakis(propane-1-sulfonate)having a structure represented by formula (II):

In one or more embodiments, the first surfactant may be thermally stableat a temperature of 200° C. or more, 250° C. or more, 300° C. or more,or 350° C. or more, as measured by thermogravimetric analysis (TGA).

In one or more embodiments, the first surfactant may be highly solublein aqueous solutions, such as in deionized water, seawater, brines,calcium chloride solutions, and the like. In some embodiments, the firstsurfactant may be soluble in aqueous solutions in an amount of 10% byweight (wt. %) or more, 20 wt. % or more, 30 wt. % or more, or 40 wt. %or more at ambient temperature. In some embodiments, the solubility ofthe first surfactant may increase with increasing temperature, untilgelation occurs.

One or more embodiments of the present disclosure are directed towellbore fluids. The wellbore fluids of one or more embodiments mayinclude, for example, water-based wellbore fluids. The wellbore fluidsmay be acid stimulation fluids or EOR fluids or among others.

In one or more embodiments, the water-based wellbore fluids may comprisean aqueous fluid. The aqueous fluid may include at least one of freshwater, seawater, brine, water-soluble organic compounds, and mixturesthereof. The aqueous fluid may contain fresh water formulated to containvarious salts in addition to the first or second salt, to the extentthat such salts do not impede the desired nitrogen-generating reaction.The salts may include, but are not limited to, alkali metal halides andhydroxides. In one or more embodiments, brine may be any of seawater,aqueous solutions wherein the salt concentration is less than that ofseawater, or aqueous solutions wherein the salt concentration is greaterthan that of seawater. Salts that are found in seawater may includesodium, calcium, aluminum, magnesium, potassium, strontium, and lithiumsalts of halides, carbonates, chlorates, bromates, nitrates, oxides,phosphates, among others. Any of the aforementioned salts may beincluded in brine. In one or more embodiments, the density of theaqueous fluid may be controlled by increasing the salt concentration inthe brine, though the maximum concentration is determined by thesolubility of the salt. In particular embodiments, brine may include analkali metal halide or carboxylate salt and/or alkaline earth metalcarboxylate salts.

The wellbore fluids of one or more embodiments may comprise the firstsurfactant in an amount of the range of about 1 to 15% by weight (wt.%). For example, the wellbore fluid may contain the first surfactant inan amount ranging from a lower limit of any of 1, 1.5, 2, 2.5, 3, 4, 5,7, 10, and 12 wt. % to an upper limit of any of 1.5, 2, 3, 4, 5, 6, 8,10, 12, 14, and 15 wt. %, where any lower limit can be used incombination with any mathematically-compatible upper limit.

As described previously, the wellbore fluid may also include a secondsurfactant. The second surfactant may be a zwitterionic surfactanthaving a structure represented by Formula (III):

where R² is a C₁₅-C₂₇ hydrocarbon group or a C₁₅-C₂₉ substitutedhydrocarbon group, R³ is a C₁-C₁₀ hydrocarbon group, and p and q areeach, independently, an integer ranging from 1 to 4.

In reference to R² and R³, the term “hydrocarbon group” has the samemeaning as discussed above with regard to R¹. As used with regard to R²,the term “substituted hydrocarbon group” refers to a hydrocarbon group(as defined above) where at least one hydrogen atom is substituted witha non-hydrogen group that results in a stable compound. Suchsubstituents may be groups selected from, but not limited to, halo,hydroxyl, alkoxy, oxo, alkanoyl, aryloxy, alkanoyloxy, amino,alkylamino, arylamino, arylalkylamino, disubstituted amines,alkanylamino, aroylamino, aralkanoylamino, substituted alkanoylamino,substituted arylamino, substituted aralkanoylamino, thiol, alkylthio,arylthio, arylalkylthio, alkylthiono, arylthiono, aryalkylthiono,alkylsulfonyl, arylsulfonyl, arylalkylsulfonyl, sulfonamide, substitutedsulfonamide, nitro, cyano, carboxy, carbamyl, alkoxycarbonyl, aryl,substituted aryl, guanidine, and heterocyclyl, and mixtures thereof. Insome embodiments, the substituted hydrocarbon group may comprise one ormore alkylene oxide units. The alkylene oxide may be ethylene oxide.

In one or more particular embodiments, the second surfactant may be azwitterionic surfactant have a structure represented by formula (IV):

In one or more embodiments, the zwitterionic surfactant may be solublein aqueous solutions, such as in deionized water, seawater, brines,calcium chloride solutions, and the like. In some embodiments, thezwitterionic surfactant may be soluble in aqueous solutions in an amountof 10% by weight (wt. %) or more, 20 wt. % or more, or 30 wt. % or moreat ambient temperature. In some embodiments, the zwitterionic surfactantmay have a lower aqueous solubility than the piperazine basedsurfactant. In some embodiments, the solubility of the zwitterionicsurfactant may increase with increasing temperature, until gelationoccurs.

The wellbore fluids of one or more embodiments may comprise the secondsurfactant in an amount of the range of about 1 to 15% by weight (wt.%). For example, the wellbore fluid may contain the second surfactant inan amount ranging from a lower limit of any of 1, 1.5, 2, 2.5, 3, 4, 5,7, 10, and 12 wt. % to an upper limit of any of 1.5, 2, 3, 4, 5, 6, 8,10, 12, 14, and 15 wt. %, where any lower limit can be used incombination with any mathematically-compatible upper limit.

In one or more embodiments, the wellbore fluid may comprise the firstsurfactant and the second surfactant in a weight ratio of 1:5 to 5:1 byweight, where the weight ratio is given as the weight of the firstsurfactant to the weight of the second surfactant. For example, thewellbore fluid may contain the first surfactant and the secondsurfactant in a weight ratio ranging from a lower limit of any of 1:5,1:4, 1:3, 1:2, 1:1, and 2:1, to an upper limit of any of 1:2, 1:1, 2:1,3:1, 4:1, and 5:1, where any lower limit can be used in combination withany mathematically-compatible upper limit.

The wellbore fluids of one or more embodiments may have a totalsurfactant content, including both the first and second surfactant, inan amount of the range of about 2 to 30% by weight (wt. %). For example,the wellbore fluid may have a total surfactant content in an amountranging from a lower limit of any of 2, 2.5, 3, 4, 5, 7, 10, 12, 15, 20,and 25 wt. % to an upper limit of any of 1.5, 2, 3, 4, 5, 6, 8, 10, 12,15, 20, 25, and 30 wt. %, where any lower limit can be used incombination with any mathematically-compatible upper limit.

The wellbore fluids may include an activator. The activator is anadditive that, upon an increase in temperature, enables the surfactantto exhibit viscoelastic behavior and cause the wellbore fluid toincrease in viscosity. Without being bound by any theory, the activatorsdisclosed herein may enable the surfactant micelles to form a rod-shapedstructure that entangle as the temperature of the fluid increases. Thisentanglement is the cause of the viscoelastic behavior and the increasein viscosity.

In one or more embodiments, the activator may be a salt. The salt may,for instance comprise a monovalent cation, such as an alkali metal or aGroup 11 transition metal, or a divalent cation, such as an alkalineearth metal or a transition metal. In some embodiments, the salt maycomprise a cation selected from the group consisting of lithium, sodium,potassium, magnesium, calcium, nickel, iron, tin, aluminum, and zinc. Insome embodiments, the salt may comprise an anion selected from the groupconsisting of fluoride, chloride, bromide, carbonate, bicarbonate,sulfate, nitrate, nitrite, chromate, sulfite, oxalate, phosphate, andphosphite. In particular embodiments, the activator may be an alkalineearth metal halide, such as calcium chloride.

The wellbore fluids of one or more embodiments may comprise theactivator in an amount of the range of about 5 to 30% by weight (wt. %).For example, the wellbore fluid may contain the activator in an amountranging from a lower limit of any of 5, 6, 7, 8, 10, 12, 15, 17, 20, and22 wt. % to an upper limit of any of 10, 12, 15, 17, 20, 22, 25, 27, and30 wt. %, where any lower limit can be used in combination with anymathematically-compatible upper limit.

In one or more embodiments, the wellbore fluid may comprise theactivator and the surfactants in a weight ratio of 30:1 to 1:3, byweight, where the weight ratio is given as the weight of the activatorto the total weight of the surfactants. For example, the wellbore fluidmay contain the activator and the surfactants in a weight ratio rangingfrom a lower limit of any of 1:3, 1:2, 1:1, 2:1, 4:1, 6:1, 8:1, 10:1 and12:1 to an upper limit of any of 1:1, 2:1, 4:1, 6:1, 8:1, 10:1, 12:1,15:1, 20:1, 25:1, and 30:1, where any lower limit can be used incombination with any mathematically-compatible upper limit.

The wellbore fluids of one or more embodiments may include one or moreacids. Acids may be particularly included when the wellbore fluid is tobe used in a matrix stimulation process, as described below. The acidmay be any suitable acid known to a person of ordinary skill in the art,and its selection may be determined by the intended application of thefluid. In some embodiments, the acid may be one or more selected fromthe group consisting of hydrochloric acid, sulfuric acid, carboxylicacids such as acetic acid, and hydrofluoric acid. In some embodiments,the hydrofluoric acid may be included as a hydrogen fluoride source,such as ammonium fluoride, ammonium bifluoride, fluoroboric acid,hexafluorophosphoric acid, and the like.

The wellbore fluid of one or more embodiments may comprise the one ormore acids in a total amount of the range of about 0.01 to 30.0 wt. %.For example, the wellbore fluid may contain the acids in an amountranging from a lower limit of any of 0.01, 0.05, 0.1, 0.5, 1.0, 5.0, 10,15, 20, and 25 wt. % to an upper limit of any of 0.5, 1.0, 5.0, 10, 15,20, 25, and 30 wt. %, where any lower limit can be used in combinationwith any mathematically-compatible upper limit.

The wellbore fluids of one or more embodiments may include one or moreadditives. The additives may be any conventionally known and one ofordinary skill in the art will, with the benefit of this disclosure,appreciate that the selection of said additives will be dependent uponthe intended application of the wellbore fluid. For instance, if thewellbore fluid is to be used as a fracturing fluid, it may comprise aproppant such as sand. In some embodiments, the additives may be one ormore selected from clay stabilizers, scale inhibitors, corrosioninhibitors, biocides, friction reducers, thickeners, and the like.

The wellbore fluid of one or more embodiments may comprise the one ormore additives in a total amount of the range of about 0.01 to 30.0 wt.%. For example, the wellbore fluid may contain the additives in anamount ranging from a lower limit of any of 0.01, 0.05, 0.1, 0.5, 1.0,2.5, 5.0, 1.5, 10.0 and 12.5 wt. % to an upper limit of any of 0.1, 0.5,1.0, 2.5, 5.0, 7.5, 10.0, 12.5, 15.0, 20.0 and 30.0 wt. %, where anylower limit can be used in combination with anymathematically-compatible upper limit.

In one or more embodiments, the wellbore fluid may contain little to nosolid material. For example, the wellbore fluids of some embodiments maycontain solid material in an amount of 2 wt. % or less, 1 wt. % or less,0.5 wt. % or less, 0.1 wt. % or less, 0.05 wt. % or less, 0.01 wt. % orless, or 0.001 wt. % or less.

In one or more embodiments, the wellbore fluid may have a density thatis greater than 0.90 g/cm³. For example, the wellbore fluid may have adensity that is of an amount ranging from a lower limit of any of 0.90,0.95, 1.00, 1.05, 1.10, 1.15, and 1.20 g/cm³ to an upper limit of any of1.00, 1.05, 1.10, 1.15, 1.20, and 1.25 g/cm³, where any lower limit canbe used in combination with any mathematically-compatible upper limit.

In one or more embodiments, the wellbore fluid may have a viscosity at40° C. that is of the range of about 1 to 30 cP. For example, thewellbore fluid may have a viscosity at 40° C. that is of an amountranging from a lower limit of any of 1, 2, 3, 4, 5, 6, 7, 8, 10, 12, and15 cP to an upper limit of any of 4, 5, 6, 8, 10, 12, 14, 16, 18, 20,22, 25, 27, and 30 cP, where any lower limit can be used in combinationwith any mathematically-compatible upper limit. In some embodiments, thewellbore fluids may have a viscosity at 40° C. of 30 cP or less, 25 cPor less, 20 cP or less, 15 cP or less, or 10 cP or less.

In one or more embodiments, the wellbore fluid may have a viscosity at90° C. that is of the range of about 150 to 400 cP. For example, thewellbore fluid may have a viscosity at 90° C. that is of an amountranging from a lower limit of any of 150, 175, 200, 225, and 250 cP toan upper limit of any of 275, 300, 325, 350, 375, and 400 cP, where anylower limit can be used in combination with anymathematically-compatible upper limit. In some embodiments, the wellborefluids may have a viscosity at 90° C. of 150 cP or more, 200 cP or more,250 cP or more, or 300 cP or more, or 350 cP or more.

The wellbore fluid of one or more embodiments may have a viscosity thatis higher at 90° C. than at 40° C. In one or more embodiments, thewellbore fluid may have a ratio of a viscosity at 90° C. to a viscosityat 40° C. that is of the range of about 5:1 to 400:1. For example, thewellbore fluids may have a ratio of a viscosity at 90° C. to a viscosityat 40° C. that is of the range having a lower limit of any of 5:1, 10:1,20:1, 30:1, 50:1, and 100:1, to an upper limit of any of 125:1, 150:1,200:1, 250:1, 300:1, 350:1 and 400:1, where any lower limit can be usedin combination with any mathematically-compatible upper limit.

In one or more embodiments, the viscosity of the wellbore fluid maydecrease after contacting with a hydrocarbon. For example, aftercontacting with a hydrocarbon such as diesel, the wellbore fluid mayhave a viscosity at 90° C. that is of an amount ranging from 5 to 200cP. In one or more embodiments, after contacting with a hydrocarbon suchas diesel, the wellbore fluid may have a viscosity at 90° C. that is ofan amount ranging from a lower limit of any of 5, 6, 7, 8, 9, 10, 15,20, 30, and 50 cP to an upper limit of any of 75, 100, 125, 150, 175 and200 cP, where any lower limit can be used in combination with anymathematically-compatible upper limit. In some embodiments, aftercontacting with a hydrocarbon such as diesel, the wellbore fluid mayhave a viscosity at 90° C. of 200 cP or less, 100 cP or less, 50 cP orless, 20 cP or less, or 10 cP or less, or 8 cP or less.

In one or more embodiments, the wellbore fluid may have a pH that isneutral or acidic. For example, the wellbore fluid may have a pH rangingfrom a lower limit of any of 2, 3, 4, 4.5, 5, 5.5, and 6, to an upperlimit of any of 3, 4, 4.5, 5, 5.5, 6, 6.5, and 7, where any lower limitcan be used in combination with any mathematically-compatible upperlimit. In some embodiments, the wellbore fluid may have a pH of 7 orless, of 6 or less, of 5 or less, of 4 or less, or of 3 or less.

One or more embodiments of the present disclosure are directed to asynthesis of the surfactant represented by the aforementioned formula(I). As shown in FIG. 1 , piperazine may be refluxed in ethyl acetate inthe presence of 1,3-propane sultone to produce the surfactantrepresented for formula (I). The reaction may be carried out at atemperature near the boiling point of ethyl acetate, such as at about 77to 78° C. In one or more embodiments, an excess of the sultone is used.A molar ratio of the piperazine to 1,3-butane sultone may be in a rangeof from 1:5 to 1:12 or, 1:7 to 1:10. The reaction mixture may berefluxed for about 6 to 24 hours. A white precipitate is formed that maythen be filtered and washed with ethyl acetate, diethyl ether andacetone. The reaction yield was 95%.

Methods in accordance with the present disclosure may comprise theinjection of a wellbore fluid into a formation. In one or moreembodiments, the wellbore fluid may be a single treatment fluid that isinjected into the wellbore in one pumping stage. In other embodiments,methods in accordance with one or more embodiments may involve theinjection of the wellbore fluid and one or more additional stimulationfluids. The additional stimulation fluids may, in some embodiments, beco-injected with the wellbore fluid. In some embodiments, thestimulation fluids may be injected after the wellbore fluid.

The wellbore fluid of one or more embodiments has a low viscosity at lowtemperatures and, therefore, good injectivity, while being thermallystable enough for use downhole. Upon exposure to increased temperaturesin the wellbore, the wellbore fluid may increase in viscosity. Thisphenomenon has the effect of reducing fluid mobility, resulting indiverting the flow from high permeability zones to lower ones and,ultimately, providing improved oil recovery.

The methods of one or more embodiments of the present disclosure mayfurther comprise a pre-flushing step before the injection of thewellbore fluid. The pre-flushing step may comprise flushing theformation with a flushing solution that comprises one or moresurfactants. The flushing solution may be an aqueous solution, and thesurfactant may be the same surfactants as included in the wellborefluid. The pre-flushing may limit the adsorption of the surfactants onthe rock surface of the formation during the injection process. Thesuitability of the use of a pre-flushing step may depend on the type ofsurfactant and rock.

The hydrocarbon-containing formation of one or more embodiments may be aformation containing multiple zones of varying permeability. Forinstance, the formation may contain at least a zone having a relativelyhigher permeability and a zone having a relatively lower permeability.During conventional injection, fluids preferentially sweep the higherpermeability zone, leaving the lower permeability zone incompletelyswept. In one or more embodiments, the increased viscosity of thewellbore fluid may “plug” the higher permeability zone, allowingsubsequent fluid to sweep the low permeability zone and improving sweepefficiency.

In one or more embodiments, the formation may have a temperature rangingfrom about 120 to 350° C. For example, the formation may have atemperature that is of an amount ranging from a lower limit of any of120, 140, 160, 180, and 200° C. to an upper limit of any of 200, 225,250, 275, 300, 325, and 350° C., where any lower limit can be used incombination with any mathematically-compatible upper limit.

The methods of one or more embodiments may be used for well stimulation.A well stimulation process in accordance with one or more embodiments ofthe present disclosure is depicted by, and discussed with reference to,FIG. 2 . Specifically, in step 200, the wellbore fluid may be injectedinto a hydrocarbon-bearing formation at an injection well. In someembodiments, the injection of the wellbore fluid may be performed at apressure that is below the fracturing pressure of the formation. In step210, a zone within the formation may be at a high temperature andincrease the viscosity of the wellbore fluid. In step 220, after theincrease in viscosity, the tail-end of the fluid is diverted tolower-permeability zones of the formation, displacing hydrocarbons. Thisresults from the increase in viscosity that may “plug” the morepermeable zones of the formation. In step 230, the formation isstimulated by the wellbore fluid, creating pathways for hydrocarbonproduction. In step 240, the displaced hydrocarbons may be recoveredthrough the stimulated reservoir. In one or more embodiments, thehydrocarbons may be recovered at a production well.

The well stimulation process of one or more embodiments may be a matrixstimulation process. In the matrix stimulation process of one or moreembodiments, the wellbore fluid, or one of the stimulation fluids,contains an acid. The acid fluid may react with the formation,dissolving rock, and creating wormholes that create a pathway forhydrocarbons to be displaced from deeper within the rock. In one or moreembodiments, the wellbore fluid may increase in viscosity in theformation, enabling the fluid to better penetrate lower-permeabilityzones of the formation and allowing the acid to more uniformly reactwith the entire formation. This may provide for the formation of deeperwormholes and enhancing the overall permeability of the near-wellboreregion. In the absence of this viscosity increase, the fluid willprimarily penetrate the high permeability zones.

In one or more embodiments, the well stimulation process may be repeatedone or more times to increase the amount of hydrocarbons recovered. Insome embodiments, subsequent well stimulation processes may involve theuse of different amounts of the surfactant and/or different surfactantsthan the first. The methods of one or more embodiments mayadvantageously provide improved sweep efficiency.

Examples

The following examples are merely illustrative and should not beinterpreted as limiting the scope of the present disclosure.

Stearic acid (95%), 3-(dimethylamino)-1-propylamine (99%), NaF (ACSreagent grade, ≥99%), 1,3-propanesultone (≥99%), ethyl acetate (HPLCgrade), diethyl ether (ACS reagent grade, ≥99.8%), piperazine (anhydrous≥99%), and acetone (ACS reagent grade, ≥99.5%) were used as-received.

A zwitterionic surfactant 10 was prepared by the synthetic routeillustrated in FIG. 3 . Specifically, the zwitterionic surfactant 10 wassynthesized by initially preparing the intermediate 8, and then thenreacting 8 with 1,3-propanesultone 9.

Synthesis of N-(3-(dimethylamino)propyl)nonadecanamide (8)

A two-necked round bottom flask, fixed with a reflux condenser and abent tube, was charged with stearic acid 6 (5.00 g, 20.63 mmol),3-(dimethylamino)-1-propylamine 7 (4.22 g, 41.25 mmol), and NaF (0.09 g,2.06 mmol). The bent tube was filled with well dried alumina, whichabsorbs any water generated by the reaction. The flask was heated at atemperature of 160° C. for eight hours under a N₂ atmosphere. A secondaliquot of 3-(dimethylamino)-1-propylamine 7 (30.94 mmol) was added andthe conditions were maintained for a further six hours. After cooling toroom temperature, the solid residue was collected, washed with coldacetone:water (93:7 mL), and dried under vacuum to yield a white solid8. ¹H-NMR [CD₃OD]=0.869 (t, 3H), 1.451-1.521 (m, 27H), 1.240-1.657 (m,4H), 2.133 (t, 2H), 2.224 (s, 6H), 2.334 (t, 2H), 3.332 (t, 2H); ¹³C-NMR[CD₃OD]=18.95, 22.14, 25.22, 28.11, 33.32, 35.68, 35.88, 44.02, 50.66,61.57, 63.46, 177.53, 180.53.

Synthesis of3-(methyliumyl(methyl)(3-stearamidopropyl)-l4-azaneyl)propane-1-sulfonate(SDAS, 10)

A 250-mL two-necked flask fixed with a reflux condenser was charged with8 (5.00 g, 15.31 mmol), 1,3-propanesultone 9 (2.81 g, 22.97 mmol), andethyl acetate (100 mL). The flask was heated at 80° C. for 12 h. Aftercooling to room temperature, the solid was collected, washedsuccessively using ethyl acetate (100 mL) and diethyl ether (50 mL), anddried under vacuum to yield SDAS 10 as a white solid (6.14 g, 89%yield). ¹H-NMR [CDCl₃]=1.101 (t, 3H), 1.451-1.521 (m, 27H), 1.805 (m,2H), 2.185 (t, 2H), 2.324-2.425 (m, 4H), 3.075 (t, 2H), 3.473 (t, 2H),3.54 (s, 6H), 3.726 (t, 2H); ¹³C-NMR [CD₃OD]=14.0, 19.3, 22.6, 23.0,25.9, 29.3, 29.6, 29.7, 31.9, 36.3, 36.4, 48.1, 50.9, 62.6, 63.2, 174.6;FTIR (cm⁻¹)=3265.42, 2915.00, 2884.61, 1666.49, 1552.64, 1467.54,1174.26, 1035.13, 723.06.

Synthesis of3,3′,3″,3′″-(piperazine-1,4-diium-1,1,4,4-tetrayl)tetrakis(propane-1-sulfonate)

A piperazine based surfactant was prepared according to the reactionscheme previously described and as shown in FIG. 1 . 1.0 g (11.60 mmol)of piperazine 2 was loaded in a round bottom flask having 20 mL of ethylacetate. Then, 1,3-propane sultone 3 (69.6 mmol) was added in thereaction flask. The oil bath was allowed to reach 99° C. and thereaction mixture was allowed to reflux for 12-14 hours. The whiteprecipitates that formed were filtered and washed with ethyl acetate,diethyl ether and acetone. Typically, 15 g of solvent was used for eachgram of product for the washing steps. The product was dried undervacuum. ¹H-NMR [D₂O]=2.096 (m, 8H), 2.914 (t, 8H), 3.240 (t, 8H), 3.51(t, 8H); ¹³C-NMR [D₂O]=20.23, 48.36, 49.82, 56.11. FTIR (cm⁻¹)=3007.99,2978.34, 1447.37, 1239.18, 1215.18, 1143.90, 952.86, 787.80.

Viscosification Experiments

The zwitterionic surfactant 10 was mixed with the piperazine basedsurfactant 1 in a weight ratio of 1:1. Each surfactant mixture was thenadded to two different concentrations of CaCl₂ in distilled water. TheCaCl₂ was used at amounts of 10% and 20% by weight of the total amountof CaCl₂ and water. Thereafter, 5 wt. % of the total surfactant mixture(2.5 wt. % SDAS 10 and 2.5 wt. % of piperazine based surfactant 1) wasadded to 95 wt. % of the 10 or 20% CaCl₂ solutions. The viscosity of thesurfactant solutions was measured at room temperature, 40° C. and at 90°C. under different shear rates. The results are provided in Table 1.

TABLE 1 Viscosity Results in CaCl₂ solutions Shear Rate Viscosity of 10%CaCl₂ solution (cPs) Viscosity of 20% CaCl₂ solution (cPs) (s⁻¹) RT 40°C. 90° C. RT 40° C. 90° C. 1.02 24.32 7.81 6047 15.23 15.76 2891 5.007.64 4.33 1374 10.33 7.91 733.4 10.00 6.56 3.19 742.4 7.28 6.32 411.815.00 6.12 3.12 510.5 6.54 5.47 292.2 20.00 5.37 2.87 393.9 5.18 4.56243.5 25.00 4.78 2.79 380.2 4.67 4.09 232.7 35.00 4.34 1.61 354.3 3.893.9 209.9

As shown, the viscosity of the surfactant solutions increasesdramatically as the temperature increases.

Gel Breaking Experiments

The gel breaking properties of the piperazine based surfactant 1 mixedwith zwitterionic surfactant 10 was studied by mixing the twosurfactants with diesel. Different quantities of diesel were mixed witha 5 wt. % solution of 1:1 ratio of surfactant 1 and surfactant 10 in a20% CaCl₂ solution as previously described. The viscosity was tested at90° C. at different shear rates. The results are shown in Table 2.

TABLE 2 Viscosity Results of Diesel in Surfactant and CaCl₂ solutionsViscosity (cPs) at 90° C. Shear 0% 1.37% 2.71% 5.27% 10.01% 14.31%21.77% 28.02% Rate diesel diesel diesel diesel diesel diesel dieseldiesel 1.02 6047 5070 5727 5547 3133 109.4 179.7 171.9 5 1374 1307 14271510 926.3 63.78 98.85 94.07 10 742.4 768.9 779.4 800.3 489 48.26 70.7873.19 15 510.5 520.72 516.62 526.92 323 43.03 56.31 63.75 20 393.9400.12 407.55 413.56 232.7 41.84 49.81 55.78 25 380.2 385.67 395.23399.41 178.8 39.53 44.31 51.64 35 354.3 370.34 379.81 365.93 129.6 34.6139.24 46.9

As shown, the mixture of surfactants showed a significant decrease inthe apparent viscosity with the addition of diesel.

The singular forms “a,” “an,” and “the” include plural referents, unlessthe context clearly dictates otherwise.

As used here and in the appended claims, the words “comprise,” “has,”and “include” and all grammatical variations thereof are each intendedto have an open, non-limiting meaning that does not exclude additionalelements or steps.

When the word “approximately” or “about” are used, this term may meanthat there can be a variance in value of up to ±10%, of up to 5%, of upto 2%, of up to 1%, of up to 0.5%, of up to 0.1%, or up to 0.01%.

Ranges may be expressed as from about one particular value to aboutanother particular value, inclusive. When such a range is expressed, itis to be understood that another embodiment is from the one particularvalue to the other particular value, along with all particular valuesand combinations thereof within the range.

While the disclosure includes a limited number of embodiments, thoseskilled in the art, having benefit of this disclosure, will appreciatethat other embodiments may be devised which do not depart from the scopeof the present disclosure. Accordingly, the scope should be limited onlyby the attached claims.

Although only a few example embodiments have been described in detail,those skilled in the art will readily appreciate that many modificationsare possible in the example embodiments without materially departingfrom the scope of the disclosure. Accordingly, all such modificationsare intended to be included within the scope of this disclosure asdefined in the following claims. In the claims, means-plus-functionclauses are intended to cover the structures described as performing therecited function and not only structural equivalents, but alsoequivalent structures. Thus, although a nail and a screw may not bestructural equivalents in that a nail employs a cylindrical surface tosecure wooden parts together, whereas a screw employs a helical surface,in the environment of fastening wooden parts, a nail and a screw may beequivalent structures. It is the express intention of the applicant notto invoke 35 U.S.C. § 112(f) for any limitations of any of the claims,except for those in which the claim expressly uses the words ‘means for’together with an associated function.

1. A wellbore fluid, comprising: a first surfactant having a structurerepresented by Formula (I):

wherein m is an integer ranging from 2 to 3, and n, o, and k are each,independently, integers ranging from 2 to 10; a second surfactant havinga structure represented by Formula (III):

wherein R² is a C₁₅-C₂₇ hydrocarbon group or a C₁₅-C₂₉ substitutedhydrocarbon group, R³ is a C₁-C₁₀ hydrocarbon group, and p and q areeach, independently, an integer ranging from 1 to 4; an alkaline earthmetal halide activator; and an aqueous base fluid.
 2. The wellbore fluidaccording to claim 1, wherein the first surfactant has a structurerepresented by formula (II):


3. The wellbore fluid according to claim 1, wherein the secondsurfactant has a structure represented by formula (IV):


4. The wellbore fluid according to claim 1, comprising 1 to 15 wt. % ofthe first surfactant.
 5. The wellbore fluid according to claim 1,comprising 1 to 15 wt. % of the second surfactant.
 6. The wellbore fluidaccording to claim 1, comprising 5 to 30 wt. % of the alkaline earthmetal halide activator.
 7. The wellbore fluid according to claim 1,further comprising an acid.
 8. The wellbore fluid according to claim 1,wherein the alkaline earth metal halide activator is CaCl₂.
 9. Thewellbore fluid according to claim 1, wherein the wellbore fluid has aviscosity at 90° C. ranging from 150 to 400 cP.
 10. A method fortreating a hydrocarbon-containing formation, comprising: injecting awellbore fluid into a high permeability zone of a hydrocarbon-containingformation, wherein the high permeability zone increases the temperatureof the wellbore fluid, resulting in the wellbore fluid having anincreased viscosity; wherein the wellbore fluid comprises: a firstsurfactant having a structure represented by Formula (I):

wherein m is an integer ranging from 2 to 3, and n, o, and k are each,independently, integers ranging from 2 to 10; a second surfactant havinga structure represented by Formula (III):

wherein R² is a C₁₅-C₂₇ hydrocarbon group or a C₁₅-C₂₉ substitutedhydrocarbon group, R³ is a C₁-C₁₀ hydrocarbon group, and p and q areeach, independently, an integer ranging from 1 to 4; an alkaline earthmetal halide activator; and an aqueous base fluid.
 11. The methodaccording to claim 10, wherein the first surfactant has a structurerepresented by formula (II):


12. The method of claim 10, wherein the second surfactant has astructure represented by formula (IV):


13. The method according to claim 10, wherein the wellbore fluidcomprises 1 to 15 wt. % of the first surfactant.
 14. The methodaccording to claim 10, wherein the wellbore fluid comprises 1 to 15 wt.% of the second surfactant.
 15. The method according to claim 10,wherein the wellbore fluid comprises 5 to 30 wt. % of the alkaline earthmetal halide activator.
 16. The method according to claim 10, whereinthe wellbore fluid further comprises an acid.
 17. The method accordingto claim 10, wherein the alkaline earth metal halide activator is CaCl₂.18. The method of claim 10, wherein the wellbore fluid has a viscosityat 90° C. ranging from 150 to 400 cP.
 19. The method of claim 10,further comprising recovering the hydrocarbons from thehydrocarbon-containing formation.